Well drilling operations are typically performed using a long assembly of threadably connected pipe sections called a drillstring. Often, the drillstring is rotated at the surface by equipment on the rig thereby rotating a drill bit attached to a distal end of the drillstring downhole. Weight, usually by adding heavy collars behind the drill bit, is added to urge the drill bit deeper as the drillstring and bit are rotated. Because subterranean drilling generates a lot of heat and cuttings as the formation below is pulverized, drilling fluid, or mud, is pumped down to the bit from the surface.
Typically, drill pipe sections are hollow and threadably engage each other so that the bores of adjacent pipe sections are hydraulically isolated from the “annulus” formed between the outer diameter of the drillstring and the inner diameter of the wellbore (either cased or as-drilled). Drilling mud is then typically delivered to the drill bit through the bore of the drillstring where it is allowed to lubricate the drill bit through ports and return with any drilling cuttings through the annulus. Because the drillstring and wellbore are often several thousand feet in depth, a tremendous amount of pressure is required to pump the drilling mud down to the bit and back up to the surface in a complete cycle. It is not unheard of for drilling mud pressures to exceed 20,000 pounds per square inch at these depths.
Alternatively, well drilling can be accomplished through the use of a “mud motor,” a device where the drilling mud flow and pressure through the drillstring is used to generate mechanical energy (through a rotor or turbine downhole) and rotate the drill bit. Mud motor systems are frequently employed where directional and/or horizontal drilling is required, for example, in deep sea operations. In mud motor arrangements, the drill string is not rotated, but is instead “slid” into the wellbore as the bit drills deeper. In order for mud motor systems to continue to operate, a differential between bore and annulus mud pressure must be maintained else the rotor or turbine assembly will not be capable of rotating the bit.
Regardless of the drilling method employed, operations of various types are performed throughout the drilling process. For instance, drill pipe sections often become stuck downhole and need to be freed. For example, directional drilling operations, wherein the drillstring is not rotated, have a higher occurrence of stuck drill pipe than traditional rotated drillstring operations. The release of stuck drill pipe is typically performed by sending a string of tools including a free-point indicator down the bore of the drillstring to determine where the pipe is stuck. Once the location is determined, reverse torque is applied to the drillstring and a charge is detonated to break the threaded joints of drill pipe free at the stuck location. With the free pipe disconnected the remainder of the drillstring can be “fished” out of the wellbore. The ability to maintain the bore and annulus of the drillstring under pressure while the recovery equipment run downhole is highly desirable.
Frequently, measurements of formation density, porosity, and permeability are made before a well is drilled deeper or before a change in drilling direction is made. Often, measurements relating to directional surveying are needed to ensure the wellbore is being drilled according to plan. Usually, these measurements and operations can be performed with a measurement while drilling assembly (MWD), whereby the measurements are made in real-time at or proximate to the drill bit and subsequently transmitted to operators at the surface through mud-pulse or electromagnetic-wave telemetry. While MWD operations are possible most of the time, manual measurements are often desired either for verification purposes or the measurements desired are not within the capabilities of the MWD system currently in the wellbore. Whatever the reason, it is desirable to maintain the differential in bore and annulus pressure downhole so that mud motors or other downhole equipment may continue to function while the operation is performed. Typically, the measurements are made by engaging a “tool” connected to a communications “conduit” within the bore of the drillstring and deploying the tool to the desired depth.
For the purposes of this disclosure, the term “tool” is very generic and may be applied to any device sent downhole to perform any operation. Particularly, a downhole tool can be used to describe a variety of devices and implements to perform a measurement, service, or task, including, but not limited to, pipe recovery, formation evaluation, directional measurement, and workover. Furthermore, the term “conduit,” while frequently thought of as a tubular member for housing electrical wires, in oilfield parlance is used to describe anything capable of transmitting hydraulic, electrical, mechanical, or light communications from one location (surface) to another (downhole). For this reason, the term conduit as applied with respect to the present disclosure is to include electrical or mechanical wireline, slick line, coiled tubing, fiber optic cable, and any present or future equivalents thereof.
Historically, the deployment of tools on a communications conduit to the bore of a drillstring has been accomplished through the use of entry subs. Entry subs, in their simplest form, include two inlets and a single outlet. Fluid (drilling mud) enters through one inlet under pressure, a communications conduit is manipulated through the second inlet, or entry port, and both the conduit and the pressurized fluid exit through the single outlet. The development of entry subs over the years has yielded various improvements to oilfield technology, but has identified numerous needs as well.
Drillstring pipe sections are preferably mounted below the entry sub at the outlet and above the sub at the fluid inlet. Frequently, entry subs are used in combination with top-drive assemblies to enable tools and the conduit attached thereto to be engaged within the bore of the drillstring while the drillstring is being rotated. With a rotational swivel located between the entry sub and the rotary table of the rig floor, the top-drive assembly is used to raise, lower, and hold the entry sub rotationally still from above while the rotary table rotates the drillstring below. This combination allows the drillstring to be rotated (and prevented from becoming stuck) while the tool disposed on the communications conduit is deployed into the bore of the drillstring. Because the entry sub provides a sealing engagement with respect to the conduit entering therethrough, drilling mud can be continued to be kept at pressure while the conduit is deployed.
Formerly, entry subs were constructed as “side entry” subs, whereby the drillstring inlet and outlet were substantially coaxial and the conduit entry port was skewed at an angle to the axis of the drillstring. Examples of a side entry sub of this type can be viewed in U.S. Reissue Pat. No. RE 33,150 issued to Harper Boyd on Jan. 23, 1990 (as a reissue of U.S. Pat. No. 4,681,162 issued on Feb. 19, 1986) both hereby incorporated by reference herein.
This arrangement required the conduit and any tool attached thereto to overcome an angle of inclination in order to pass through the tool body en route to the lower pipe section. For this reason, only the smallest and most flexible of tools (and conduits) were capable of being used with the side entry sub, severely limiting the benefits of using the device. Larger, more rigid, tools required the bottom drillstring connection to be separated (preventing the maintenance of drilling fluid bore pressure) while the tools were “made up” and inserted into the bore of the drillstring. These tools would be connected to the conduit (previously stripped through the side entry port) and run partially into the drillstring before the connection between the side entry sub and the drillstring (as well as the drilling fluid pressure) could be restored. These operations required a lengthy break in mud flow operations that could be costly in terms of rig time.
Over time, entry subs were improved and were developed as top entry subs, whereby inlet and outlet drillstring pipe sections are no longer co-axial. Preferably, the conduit entry port (top entry port) was located substantially coaxial with the lower drillstring outlet so that the inlet drillstring connection was skewed at an angle to the axis formed by the top entry port and the lower drillstring. Examples of a top entry sub of this type can be viewed in U.S. Pat. No. 5,284,210 issued on Feb. 8, 1994 to Charles M. Helms and Charles W. Bleifeld hereby incorporated herein by reference. This “bend the fluid instead of bend the tools” approach was a success and resulted in adoption throughout the industry.
However, another primary function of the top entry sub (as a member of the drillstring) is to support the total weight of the complete length of the drillstring. To manipulate the drillstring up and down into the well, the top-drive assembly (or derrick crane lifting block) must be capable of lifting several thousand feet of steel drill pipe at one time. While the drilling fluid serves to buoy some of this total weight, lengthy drillstrings frequently weigh hundreds of thousands of pounds, depending on their length, diameter, and sidewall thickness. As an integral component of the drillstring when installed, the top entry sub must also be capable of supporting loads of this type. However, much concern arose with the loading capabilities of the top entry sub because of the axial offset between the bottom drillstring connection and the top drillstring connection. This offset, while allowing a conduit and tools attached thereto to be engaged straight into the drillstring without overcoming a bend angle, could potentially induce bending moments and loads in the body of the top entry sub if high tensile loads were applied across drillstring inlet and drillstring outlet ports.
As a result of these concerns, investigations were performed to determine the bending moments experienced across the top entry sub and within the rotary threaded connections for the drillstring components attached thereto. While the results indicate that the bending loads and moments are not a significant factor, there is still the perception by some in the industry that the loads remain a factor. Additionally, as drilling technology progresses, deeper and smaller diameter wells are being drilled everyday, particularly offshore in deep water situations. Therefore, the offset nature of the top entry sub may again become an issue in that deeper wells require longer lengths of pipe, resulting in even higher tensile loads. Furthermore, the smaller “gauge” drillstring that may be employed would require a similarly gauged top entry sub, one that may not, if produced, be capable of carrying the higher tensile loads without incurring the problems associated with bending moments. An entry sub arrangement capable of both allowing tools disposed upon a communications conduit to be engaged into the bore of a drillstring and handling extreme tensile drillstring loads would be highly desirable.